1. Field of the Disclosure
The present subject matter is generally directed to drilling mud cooling systems, and in particular, to systems and methods that may be used for cooling drilling mud in onshore drilling applications.
2. Description of the Related Art
During a typical well drilling operation, such as when drilling an oil and gas well into the earth, a drilling mud circulation and recovery system is generally used to circulate drilling fluid, i.e., drilling mud, into and out of a wellbore. The drilling mud provides many functions and serves many useful purposes during the drilling operation, such as, for example, removing drill cuttings from the well, controlling formation pressures and wellbore stability during drilling, sealing permeable formations, transmitting hydraulic energy to the drilling tools and bit, and cooling, lubricating, and supporting the drill bit and drill assembly during the drilling operations.
Drilling muds commonly include many different types of desirable solid particles that aid in performing one or more of the functions and purposes outlined above. The solids particles used in drilling muds may have one or more particular properties which make their presence in a given drilling mud mixture desirable and beneficial. For example, some solids particles may need to be of a certain size or size range, which may be useful in sealing off more highly permeable formations so as to prevent the loss of valuable drilling fluid into the formation—so-called “lost circulation materials.” Other solids particles may need to be of a certain density so as to control and balance forces within the wellbore, which may be added to the drilling mud as required to guard against wellbore collapse or a well blowout during the drilling operations. High density particulate materials, such as barium sulfate, or barite, (BaSO4), and the like are often used for this purpose, as their greater unit volumetric weight serves to counterbalance high formation pressures and/or the mechanical forces caused by formations that would otherwise cause sloughing. In still other cases, solids particles may be added to the drilling mud based on a combination of the particle size and density, such as when a specific combination of the two properties may be desirable. Furthermore, the drilling mud in general, and the added solid particles in particular, can be very expensive. As such it is almost universally the case that, upon circulation out of the wellbore, the desirable - and valuable - solids particles are generally recovered and re-used during the ongoing drilling cycle.
Once the drilling mud has served its initial purposes downhole, the mud is then circulated back up and out of the well so that it can carry the drill cuttings that are removed from the advancing wellbore during the drilling operation up to the surface. As may be appreciated, the drill cuttings, which are also solids particles, are generally thoroughly mixed together with the desirable solids particles that, together with various types of fluids, make up the drilling mud, and therefore must be separated from the desirable solids particles, such as barite and the like. In the best possible drilling scenario, it is advantageous for the drill cuttings to be substantially larger than the desirable solids particles making up the drilling mud, thus enabling most of the drill cuttings to be removed using vibratory separator devices that separate particles based upon size, such as shale shakers and the like. However, in many applications, a portion of the drill cuttings returning with the drilling mud are similar in size, or even smaller than, at least some of the desirable solids particles contained in the drilling mud, in which case secondary separation devices, such as hydrocyclone and/or centrifuge apparatuses, are often employed so as to obtain further particle separation.
There are a variety of reasons why it is desirable, and even necessary, to remove as many of the drill cuttings particles from the drilling mud mixture as possible. A first reason would be so as to control and/or maintain the drilling mud chemistry and composition within a desirable range as consistently as possible. For example, the presence of drill cuttings particles in the drilling mud mixture may have a significant effect on the weight of the mud, which could potentially lead to wellbore collapse, and/or a blowout scenario associated with overpressure conditions within the well. More specifically, since the specific gravity of the drill cuttings particles are often significantly lower than that of the desired solids particles in the drilling mud, e.g., barite, the presence of cuttings particles left in the mud by the typical solids removal processes can cause the weight of the drilling mud to be lower than required in order to guard against the above-noted drilling conditions.
The temperature of the drilling mud may also significantly increase as it is being circulated down into and back up out of the drilled wellbore, particularly in high pressure and/or high temperature drilling operations. Elevated drilling mud temperatures can generally cause increased wear and tear on mud circulation equipment, thus potentially leading to premature equipment failure, increased frequency of equipment maintenance, associated shutdown (or non-productivity) time, and/or reduced overall equipment efficiency, thus adversely impacting overall drilling costs. Additionally, high drilling mud temperatures can also have a negative influence on the operation and/or performance of measurement while drilling (MWD) equipment, such as high signal attenuation and the like, or even a loss of communication with the MWD equipment during drilling operations. According, and depending on the specific downhole temperature conditions during drilling operations, the drilling mud must often be cooled prior to it being recirculating back down into the wellbore.
FIG. 1 schematically depicts a representative prior art drilling mud system 100 that is used to circulate and treat drilling mud during a typical drilling operation. As shown in FIG. 1, a blow-out preventer (BOP) 103 is positioned on a wellhead 102 as drilling operations are being performed on a wellbore 101. In operation, hot drilling mud 110h mixed with drill cuttings 107 is circulated out of the wellbore 101 and exits the BOP 103 through the bell nipple 104, and thereafter flows through the flow line 105 to the drill cuttings separation equipment 106. As noted above, depending on the particle sizes of the returning drill cuttings 107 and the degree of particle separation required, the drill cuttings separation equipment 106 may include first stage separating equipment, such as one or more vibratory separators (e.g., shale shakers), as well as second stage separating equipment, such as one or more hydrocyclone and/or centrifuge apparatuses. However, for simplicity of illustration and discussion, the drill cuttings separation equipment 106 has been schematically depicted in FIG. 1 as a shale shaker device, and therefore will hereafter be referred to as the shale shaker 106.
After entering the shale shaker 106, the undesirable drill cuttings 107 are separated from the hot drilling mud 110h and directed to a waste disposal tank or pit 108. The separated hot drilling mud 110h then flows from the sump 109 of the shale shaker 106 to a hot mud pit or hot mud tank 111h. Typically, the hot mud tank 111h is a large container having an open top so that the hot drilling mud 110h can be exposed to the environment. In this way, at least some of the heat that is absorbed by the drilling mud during the drilling operation (e.g., from the surrounding formation and/or from the generation of drill cuttings) can be released to the environment, thus allowing the hot drilling mud 110h to naturally cool, as indicated by heat flow lines 113.
In some applications, the temperature of the hot drilling mud 110h exiting the bell nipple 104 and flowing to the separation equipment (shale shaker) 106 can be as high as approximately 175° F.-225° F. It should be appreciated that the degree of natural or passive cooling that can take place in the hot mud tank 111h is generally limited by the surrounding environmental conditions, such as ambient temperature and/or relative humidity, which can be affected by numerous factors. For example, some such natural cooling factors include the geographical location of the wellbore drilling site (e.g., arctic, temperate, tropical, and/or equatorial regions, etc.), the time of year (e.g., the season or month), and even the time of day (e.g., night or day). Therefore, the amount of passive cooling is typically only incremental in nature, e.g., limited to no more than approximately a 5° F. reduction in mud temperature. In such cases, an enhanced degree of mud cooling is often required so as to further reduce the drilling mud temperature to a manageable level.
When additional mud cooling is required, the hot drilling mud 110h is further cooled in a mud cooler, such as the prior art mud cooler 130 shown in FIG. 1. In the configuration depicted in FIG. 1, a hot mud pump 131 is used to pump the hot drilling mud 110h from the hot mud tank 111h to a mud coil 132 of the mud cooler 130. As the hot drilling mud 110h passes through the mud coil 132, a water feed pump 134 is used to pump water 135 from a water tank 136 to an internal spray header 137, which sprays the water 135 downward over the mud coil 132. Simultaneously, one or more induced draft fans 133 located at the top of the mud cooler 130 generate an upward flow of air 138 across the mud coil 132. In operation, the downward spray of water 135 from the spray header 137 and the upward flow of air 138 through the fans 133 acts to cool the hot drilling mud 110h flowing through the mud coil 132 by a combination of evaporative cooling and quenching of the coil, as indicated by the heat flow lines 139. Water 135 sprayed from the internal spray header 134 is collected in a collection tray or collection tank 140 at the bottom of the mud cooler 130, from which it is then pumped back to the water tank 136 by a water recycle pump 141 for further mud cooling operations in the mud cooler 130, as described above. Under optimal conditions, a typical prior art mud cooler that is configured and operated in similar fashion to the mud cooler 130 shown in FIG. 1 can generally achieve a further mud temperature reduction that ranges from 15° F-20° F.
After the above-described mud cooling process, cooled drilling mud 110c exits the mud cooler 130. In some configurations of the prior art system 100, the cooled drilling mud 110c is directed to a cooled mud tank 111c, where it may be further treated by adding desired solids and/or chemicals so as to appropriately adjust the rheology and/or other characteristics of the mud prior to pumping the cooled drilling mud 110c back into the wellbore 101. Additionally, a further incremental temperature reduction of the mud 110c may again occur in the cooled mud tank 111c by way of passive cooling 113 to the ambient environment, as previously described with respect to the hot mod tank 111h. 
As shown in FIG. 1, after the above described separating, cooling, and/or treating operations, the drilling mud 110c flows from the cooled mud tank 111c to a mud pump 116 through the suction line 115. In some applications, a mud booster pump 114 may be used to deliver the drilling mud 110 through the suction line 115 and to the suction side of the mud pump 116. In operation, the mud pump 116 increases the pressure of the drilling mud 110 and discharges the pressurized drilling mud 110 to a standpipe 117, after which the mud 110 flows through a rotary line 118 to a swivel 119 mounted at the upper end of a kelly 120. The kelly 120 then directs the drilling mud 110c down to the drill pipe/drill string 121, and the mud 110c is recirculated down the drill string 121 to a drill bit (not shown), where it once again provides, among other things, the cooling, lubrication, and drill cutting removal tasks previously described.
In other configurations, the system 100 may not include the cooled mud tank 111c shown in FIG. 1, or the system 100 could be configured to include appropriate valving so that the cooled mud tank 111c can be bypassed. In such configurations, the cooled drilling mud 110c flows directly from the mud cooler 130 and through the suction line 115 to the suction side of the mud pump 116, where it is then pumped back into the wellbore 101 as previously described.
Additionally, the prior art system 100 can also be configured in such a way so that it can be operated in a mud cooler bypass mode. For example, as shown in FIG. 1, appropriate valving can be positioned within the system 100 and operated in such a way as to isolate the mud cooler 130 from the flow of hot drilling mud 110h exiting the hot mud tank 111h. In such configurations, the system 100 can be operated so that the hot mud 110h flows directly from the hot tank 111h to the cooled mud tank 111c, e.g., through a mud cooler bypass line 130b. It should also be appreciated that when a cooled mud tank 111c is not provided, or when the cooled mud tank 111c is also bypassed (as described above), the hot drilling mud 110h will flow directly to the mud pump 116. Such operational configurations can be used when maintenance is required on the mud cooler 130, or during drilling operations wherein the temperature of the hot drilling materials mixture exiting the wellbore 101 does not require any additional cooling beyond the incremental passive capabilities of the hot and/or cold mud tanks 111h and 111c. 
It should be appreciated that, even when a mud cooler 130 is included in the system 100, various conditions and/or operational parameters can act to detrimentally impact the overall mud temperature reduction capabilities of the system 100, and can also contribute to an increase in overall drilling costs. More specifically, as noted above, the passive cooling capabilities of the hot and/or cold mud tanks 111h and 111c are generally significantly influenced by the surrounding environmental conditions at a given wellbore drilling site. For example, in regions where the ambient temperature conditions can be very high (e.g., 100° F. or higher)—such as in Middle Eastern, northern African, southern United States, and/or Central American locations—the passive natural cooling effects obtained from the mud tanks 111h and/or 111c can be severely limited, such as a maximum of approximately 5° F. reduction in mud temperature, or even less. In similar fashion, such high temperature and/or high relative humidity environments can also reduce the evaporative cooling effects of the mud cooler 130, such that the maximum temperature reduction achievable under such conditions is no more than approximately 10° F.-15° F., or even less. Therefore, even when the mud cooler 130 is employed as part of the system 100, the drilling mud temperature can often remain at or above approximately 150° F.-175° F.
Additionally, due to the quenching effects of the water spray system (i.e., elements 134-140) described above, the hot drilling mud 110h circulating through the mud coil 132 can often cake up and adhere to the inside surfaces of the coil 132. Such mud caking effects can reduce the available flow area through the mud coil 132, thus increasing pressure drop through the coil 132. Furthermore, the insulating effects attributable to the caked layer of drilling mud on the inside surfaces of the mud coil 132 can also directly reduce the overall heat transfer/cooling capabilities of the mud cooler 130. Moreover, due to the mud caking inside of the mud coil 132, the mud cooler 130 must also be bypassed and shut down on a periodic basis for cleaning and maintenance, so that the caked drilling mud can be removed from the coil 132. Accordingly, during such periodic cleaning and maintenance activities, the only mud cooling provided by the system 100 is the relatively small amount of passive incremental cooling 113 that occurs naturally to the surrounding environment, e.g., from the hot and/or cold mud tanks 111h and 111c. 
Furthermore, due to the basic evaporative cooling effects of the mud cooler 130, it should be understood that some amount of the water 135 circulating through the cooler 130 will continuously be lost to the surrounding environment. For example, and depending on the specific ambient conditions in the area where the drilling operations are being performed, as much as 15-20 gallons per minute (gpm), or even more, of the water 135 may be lost to the ambient atmosphere during the operation of the mud cooler 130. Consequently, the supply of water 135 that is lost to the surrounding environment must periodically be replenished, such as from a portable water tanker 142, as shown in FIG. 1. Furthermore, it should be appreciated that in at least some remote and/or desert-like locations, such as drilling sites located in the Middle East and the like, water is oftentimes a precious commodity that may command a significant price, a situation that may be compounded by the generally high local ambient temperatures. Therefore, the replenishment of significant water losses to the surrounding environment during operation of the mud cooler 130 can have a substantial impact on the overall costs of drilling.
Accordingly, there is a need in the drilling industry for a mud cooling system that is less susceptible to the vagaries of the surrounding environmental conditions, and which does not require a continuous replenishment of a cooling water supply. The present disclosure is directed to mud cooling systems and methods of operating the same that may be used to mitigate, or possibly even eliminate, at least some of the problems associated with the prior art mud cooling systems described above.